Natural gas, that is, a mixture of methane and small amounts of ethane, is often recovered from oil wells as part of the "associated" gas, which also includes significant amounts of other hydrocarbons such as propane, butane, etc. collectively known as natural gas liquids. In situ under high formation pressure, these gases are either compressed into liquids or are dissolved in the heavier hydrocarbon fractions, hence the name associated gas. As pressure is released during oil recovery, the lighter components again become gaseous. Besides hydrocarbons, associated gas also may contain carbon dioxide, nitrogen and hydrogen sulfide, which must be removed prior to utilizing the natural gas as fuel or chemical feedstock. Carbon dioxide and nitrogen detract from the heating value of the gas, while hydrogen sulfide is highly corrosive and noxious. Another common component of associated gas is water vapor which must also be removed.
In recent years, enhanced oil recovery processes have gained in importance due to the escalating price of petroleum products and the decline in oil reserves. In such processes, gases such as carbon dioxide or nitrogen are injected into the oil formation at strategic locations in order to drive normally unrecoverable oil to the production well. The injected gas becomes part of the associated gas leaving the well and must be separated as described above. Generally, a separation process must take account of the fact that the life of an oil well spans a number of years, and over that time the production rate may vary widely. In the initial years of production, little or no injected fluid is needed to maintain an adequate production level. However, as the well ages it becomes increasingly difficult to recover the petroleum. This is due in part to a decrease in formation pressure caused by prior years' production, but more importantly, a large portion of the crude petroleum is often "bound" to the surrounding formation and cannot be recovered absent some extraordinary means, hence, the need for injection of carbon dioxide or nitrogen. Generally, CO.sub.2 is preferred in shallower carbonate oilbearing formations, while N.sub.2 is used for deep wells.
The composition of the associated gas changes over time as more and more gas injectant is injected to maintain a given production rate. Thus, for example, the associated gas can have a carbon dioxide content of anywhere from 0 to 90 mole percent depending on the age of the well.
In enhanced recovery processes, the separation of injectant in the associated gas is important from the standpoint of obtaining usable natural gas and natural gas liquids, and even more importantly, for recycling the injection fluid in pure form. Injection fluid such as carbon dioxide has a high initial cost and, in the quantities needed, is expensive to transport and store. Separation and purification is therefore necessary from an economic standpoint. Apparatus for doing this should be capable of handling the entire range of CO.sub.2 compositions, i.e., CO.sub.2 levels of from essentially nil to 90 mole percent, and desirably the apparatus should produce sweetened residual natural gas and natural gas liquids for sale.
The prior art has heretofore utilized cryogenic distillation and absorption processes for separation and purification of associated gas components. A number of problems are encountered, however, when these processes are applied to carbon dioxide. The cryogenic separation of carbon dioxide and methane, for example, is complicated by the phase characteristics of CO.sub.2 at distillation temperatures and pressures which give the most complete separation. Under certain conditions, carbon dioxide may "freeze out" of the distillation and in the process clog the apparatus. U.S. Pat. No. 4,318,723 seeks to avoid this by the addition of "solids-preventing agents" which permit distillation in the pressure-temperature region where solids would otherwise potentially occur. Thereby it is taught that near complete separation of CO.sub.2 and methane is achieved without solids formation.
With regard to the removal of hydrogen sulfide from an associated gas stream, the use of absorption solvents has been known. U.S. Pat. No. 4,097,250 recites the use of dimethyletherdipolyglycol and propylene carbonate for this purpose. The desulfurization step occurs under conditions of relatively high temperatures (20.degree. C. to 100.degree. C.) and high pressures in the range from 100 to 200 kilograms/sq.cm. absolute (1422 psia to 2844 psia). Apparatus designed to withstand and handle such high pressures are often expensive. The major disadvantage in using these solvents, however, is that they co-absorb the majority of the natural gas liquids with the H.sub.2 S. The circulation of solvent is thereby increased and it is difficult to recover the natural gas liquids for sale.
U.S. Pat. No. 4,293,322 also deals with the separation of hydrogen sulfide from carbon dioxide. This patent suggests adding a C.sub.3 -C.sub.6 alkane, a mixture of C.sub.3 -C.sub.6 alkanes, SO.sub.2 or SO.sub.3 solvent to improve the distillative separation. Due to the low molecular weight of these solvents, the loss of solvent becomes significant and is difficult to avoid. Since the alkane solvent is extracted from the alkane portion in the feed associated gas, the regeneration energy consumption is comparatively high when using the lighter molecular weight alkane solvents (C.sub.3 -C.sub.5). When C.sub.5 + alkane solvents are used, sticky and waxy material originally contained in the feed is extracted. In addition, the solvent used in the plant operation is sensitive to the plant feed, which causes difficulties in maintaining optimum solvent circulation. The major disadvantage, however, of using an alkane based solvent is its poor selectivity between CO.sub.2 and H.sub.2 S compared to aromatic based solvents. Lesser selectivity or lesser relative volatility between CO.sub.2 and H.sub.2 S requires a higher reflux rate to facilitate distillation and higher solvent circulation rate. As a result, the refrigeration and solvent regeneration duties are both increased.
There thus remains a need for a more efficient separation process for recovery of natural gas and carbon dioxide from the associated gases from an oil well, in which moderate pressures are used and conditions of potential carbon dioxide freezing are avoided.